Clayton Williams Energy (CWEI) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	75-2396863
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Six Desta Drive - Suite 6500
Midland, Texas	79705-5510
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (432) 682-6324

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

There were 12,164,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 1, 2013.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

	PART I.  FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	3
	Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months and nine months ended September 30, 2013 and 2012	5
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2013	6
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
	PART II. OTHER INFORMATION
Item 1A.	Risk Factors	45
Item 6.	Exhibits	46
	Signatures	47

2

PART I.  FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) ASSETS
	September 30, 2013			December 31, 2012
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	23,209		$	10,726
Accounts receivable:
Oil and gas sales	37,828			32,371
Joint interest and other, net of allowance for doubtful accounts of $1,181 at September 30, 2013 and $1,193 at December 31, 2012	10,173			16,767
Affiliates	27,544			353
Inventory	36,986			41,703
Deferred income taxes	10,623			8,560
Fair value of derivatives	2,139			7,495
Prepaids and other	8,219			6,495
	156,721			124,470
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,364,117			2,570,803
Pipelines and other midstream facilities	52,693			49,839
Contract drilling equipment	94,260			91,163
Other	20,574			20,245
	2,531,644			2,732,050
Less accumulated depreciation, depletion and amortization	(1,334,165		)	(1,311,692		)
Property and equipment, net	1,197,479			1,420,358
OTHER ASSETS
Debt issue costs, net	8,074			10,259
Fair value of derivatives	1,038			4,236
Investments and other	16,398			15,261
	25,510			29,756
	$	1,379,710		$	1,574,584
The accompanying notes are an integral part of these consolidated financial statements.

3

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) LIABILITIES AND STOCKHOLDERS' EQUITY
	September 30, 2013		December 31, 2012
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	67,232	$	73,026
Oil and gas sales	35,458		32,146
Affiliates	647		164
Accrued liabilities and other	21,961		15,578
	125,298		120,914
NON-CURRENT LIABILITIES
Long-term debt	672,625		809,585
Deferred income taxes	139,202		155,830
Asset retirement obligations	49,647		51,477
Deferred revenue from volumetric production payment	31,579		37,184
Accrued compensation under non-equity award plans	13,121		20,058
Other	909		920
	907,083		1,075,054
COMMITMENTS AND CONTINGENCIES (Note 15)
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued	—		—
Common stock, par value $.10 per share, authorized — 30,000,000 shares: issued and outstanding — 12,164,536 shares at September 30, 2013 and December 31, 2012	1,216		1,216
Additional paid-in capital	152,527		152,527
Retained earnings	193,586		224,873
	347,329		378,616
	$	1,379,710	$	1,574,584

The accompanying notes are an integral part of these consolidated financial statements.

4

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Unaudited) (In thousands, except per share)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
REVENUES
Oil and gas sales	$	104,004		$	101,638		$	296,146		$	308,116
Midstream services	1,146			671			3,373			1,305
Drilling rig services	4,044			5,348			12,896			11,478
Other operating revenues	1,971			106			4,533			543
Total revenues	111,165			107,763			316,948			321,442
COSTS AND EXPENSES
Production	25,651			32,564			83,254			93,937
Exploration:
Abandonments and impairments	609			306			2,980			2,292
Seismic and other	177			2,710			3,541			5,445
Midstream services	392			508			1,318			956
Drilling rig services	3,239			5,335			12,704			12,164
Depreciation, depletion and amortization	34,928			37,661			109,863			103,486
Impairment of property and equipment	709			—			89,811			5,711
Accretion of asset retirement obligations	1,049			1,069			3,169			2,628
General and administrative	10,030			5,830			20,401			25,133
Other operating expenses	463			207			1,869			485
Total costs and expenses	77,247			86,190			328,910			252,237
Operating income (loss)	33,918			21,573			(11,962		)	69,205
OTHER INCOME (EXPENSE)
Interest expense	(9,262		)	(9,786		)	(30,106		)	(27,817		)
Gain (loss) on derivatives	(8,278		)	(21,901		)	(9,919		)	9,856
Other	474			(559		)	2,007			739
Total other income (expense)	(17,066		)	(32,246		)	(38,018		)	(17,222		)
Income (loss) before income taxes	16,852			(10,673		)	(49,980		)	51,983
Income tax (expense) benefit	(5,901		)	3,497			18,693			(18,558		)
NET INCOME (LOSS)	$	10,951		$	(7,176	)	$	(31,287	)	$	33,425
Net income (loss) per common share:
Basic	$	0.90		$	(0.59	)	$	(2.57	)	$	2.75
Diluted	$	0.90		$	(0.59	)	$	(2.57	)	$	2.75
Weighted average common shares outstanding:
Basic	12,165			12,164			12,165			12,164
Diluted	12,165			12,164			12,165			12,164

The accompanying notes are an integral part of these consolidated financial statements.

5

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited) (In thousands)
	Common Stock			Additional					Total
	No. of	Par		Paid-In		Retained			Stockholders’
	Shares	Value		Capital		Earnings			Equity
BALANCE,
December 31, 2012	12,165	$	1,216	$	152,527	$	224,873		$	378,616
Net loss	—	—		—		(31,287		)	(31,287		)
BALANCE,
September 30, 2013	12,165	$	1,216	$	152,527	$	193,586		$	347,329

The accompanying notes are an integral part of these consolidated financial statements.

6

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)
	Nine Months Ended
	September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(31,287	)	$	33,425
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	109,863			103,486
Impairment of property and equipment	89,811			5,711
Abandonments and impairments	2,980			2,292
Gain on sales of assets and impairment of inventory, net	(1,527		)	(58		)
Deferred income tax expense (benefit)	(18,693		)	18,558
Non-cash employee compensation	(5,897		)	2,200
(Gain) loss on derivatives	9,919			(9,856		)
Cash settlements of derivatives	(1,364		)	(4,961		)
Accretion of asset retirement obligations	3,169			2,628
Amortization of debt issue costs and original issue discount	2,281			1,587
Amortization of deferred revenue from volumetric production payment	(6,639		)	(5,862		)
Changes in operating working capital:
Accounts receivable	(188		)	7,150
Accounts payable	(4,060		)	(5,772		)
Other	5,513			7,355
Net cash provided by operating activities	153,881			157,883
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(208,022		)	(438,482		)
Proceeds from volumetric production payment	1,034			45,032
Proceeds from sales of assets	197,941			867
Decrease in equipment inventory	5,818			64
Other	(1,169		)	(195		)
Net cash used in investing activities	(4,398		)	(392,714		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	43,000			240,000
Repayments of long-term debt	(180,000		)	—
Net cash provided by (used in) financing activities	(137,000		)	240,000
NET INCREASE IN CASH AND CASH EQUIVALENTS	12,483			5,169
CASH AND CASH EQUIVALENTS
Beginning of period	10,726			17,525
End of period	$	23,209		$	22,694
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	20,968		$	19,295

The accompanying notes are an integral part of these consolidated financial statements.

7

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation,)  is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico.  Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  Approximately 26% of CWEI's outstanding Common Stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board, President and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

Substantially all of our oil and gas production is sold under short-term contracts, which are market-sensitive.  Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels, and overall domestic and foreign economic conditions.

2. Presentation

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.

The consolidated financial statements include the accounts of CWEI and its wholly-owned subsidiaries.  We account for our undivided interest in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships.  Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships.  Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated. 

In the opinion of management, our unaudited consolidated financial statements as of September 30, 2013 and for the three and nine month periods ended September 30, 2013 and 2012 include all adjustments, which are of a normal and recurring nature, that are necessary for a fair presentation in accordance with GAAP.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2013.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2012.

3. Long-Term Debt

Long-term debt consists of the following:

	September 30, 2013		December 31, 2012
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $375 at September 30, 2013 and $415 at December 31, 2012	$	349,625	$	349,585
Revolving credit facility, due November 2015	323,000		460,000
	$	672,625	$	809,585

8

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Senior Notes

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (“2019 Senior Notes”).  The 2019 Senior Notes were issued at face value and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011.  In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000.  We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at September 30, 2013 and December 31, 2012.

Effective October 1, 2013, we issued an additional $250 million aggregate principal amount of 2019 Senior Notes.  The notes were sold at 100% of par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture (see Note 19).

Revolving Credit Facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $470 million, limited to the amount of a borrowing base as determined by the banks.  The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.

In connection with the sale of our Andrews County assets discussed in Note 5, we entered into an amendment to our revolving credit facility, pursuant to which the banks decreased the aggregate commitment and borrowing base under our revolving credit facility from $585 million to $470 million in April 2013. At September 30, 2013, we had $323 million of borrowings outstanding under our revolving credit facility, leaving $141.9 million available under the facility after allowing for outstanding letters of credit totaling $5.1 million.  On October 1, 2013, we used the net proceeds from our issuance of an additional $250 million aggregate principal amount of 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. In connection with the issuance of the additional 2019 Senior Notes the borrowing base was reduced to $407.5 million. After giving pro forma effect to the application of net proceeds and the reduction in borrowing base, we had $323.4 million available as of September 30, 2013.

 Our revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in our revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under our revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC (see note 18).

At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year.  We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50%.  The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the nine months ended September 30, 2013 was 2.7%.

9

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Our revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1.  Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.  In connection with the issuance of additional Senior Notes due 2019 effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014.  The computations of consolidated current assets, current liabilities, EBITDAX and funded indebtedness are defined in our revolving credit facility.  We were in compliance with all financial and non-financial covenants at September 30, 2013 and December 31, 2012.

4. Acquisition of Southwest Royalties, Inc. Limited Partnerships

On March 14, 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner (“SWR Partnerships”), into SWR, with SWR continuing as the surviving entity in the mergers. At the effective time of the mergers, all of the units representing limited partnership interests in the SWR Partnerships, other than those held by SWR, were converted into the right to receive cash. SWR did not receive any cash payment for its partnership interests in the SWR Partnerships. However, as a result of the mergers, SWR acquired 100% of the assets and liabilities of the SWR Partnerships. SWR paid aggregate merger consideration of $38.6 million in the mergers. Pro forma financial information is not presented as it would not be materially different from the information presented in the consolidated statements of operations and comprehensive income (loss) of CWEI.

To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million.  Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents ("BOE") of estimated future oil and gas production from certain properties derived from the mergers.  The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and are to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties.  Once the scheduled volumes have been delivered to the third party, the term overriding royalty interest will terminate.  SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks related to the adequacy of the associated reserves to fully recoup the scheduled volumes and also assumed all risks associated with product prices.  As a result, the VPP has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced (see Note 7).

The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Cash and cash equivalents	$	4,118
Oil and gas properties	41,098
Other non-current assets	210
Total assets acquired	45,426
Asset retirement obligations	(6,864		)
Total liabilities assumed	(6,864		)
Net assets acquired	$	38,562

5. Sales of Assets

On April 24, 2013, we closed a transaction to monetize a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities (the “Assets”). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. At closing, we contributed 5% of the Assets to a newly formed limited partnership in exchange for a 5% general partner interest, and a unit of GE Energy Financial Services contributed cash of $215.2 million to the limited partnership in exchange for a 95% limited partnership interest. The limited partnership then purchased 95% of the Assets from us for $215.2 million, subject to customary closing adjustments, with $26.5 million being placed in escrow pending resolution of certain title

10

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

requirements. If the title requirements are not satisfied, waived or extended within 180 days, the affected properties will be conveyed back to us and the escrowed funds will be returned to the limited partner. As of October 15, 2013, the buyer has exercised its right to extend the post-closing cure deadline an additional 180 days. We believe that the defects will be cured timely and have a remaining $25.9 million escrow balance as an account receivable from affiliate in the accompanying consolidated balance sheet at September 30, 2013. Upon the attainment by the limited partner of predetermined rates of return, our general partner interest in the partnership may increase.

Also in April 2013, we sold a 75% interest in our rights to the base of the Delaware formation in approximately 12,000 net undeveloped acres in Loving County, Texas to a third party for $6.8 million in cash. Under the terms of the agreement, the third party is required to carry us for all drilling and completion costs on six wells attributable to our retained 25% working interest. We retained all rights to intervals below the Delaware formation, including the Bone Springs and Wolfcamp formations.

6. Asset Retirement Obligations

We record asset retirement obligations (“ARO”) associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life.  The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

The following table reflects the changes in the ARO during the nine months ended September 30, 2013 and the year ended December 31, 2012:

	September 30, 2013				December 31, 2012
	(In thousands)
Beginning of period	$	51,477			$	40,794
Additional ARO from new properties	453			��	7,868
Sales or abandonments of properties	(4,863		)		(2,184		)
Accretion expense	3,169				3,696
Revisions of previous estimates	(589		)		1,303
End of period	$	49,647			$	51,477

7. Deferred Revenue from Volumetric Production Payment

The net proceeds from the VPP discussed in Note 4 are recorded as a non-current liability in the consolidated balance sheets.  Deferred revenue from VPP will be amortized over the life of the VPP and will be recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss).

The following table reflects the changes in the deferred revenue during the nine months ended September 30, 2013 and the year ended December 31, 2012:

	September 30, 2013			December 31, 2012
	(In thousands)
Beginning of period	$	37,184		$	—
Deferred revenue from VPP	1,034			45,479
Amortization of deferred revenue from VPP	(6,639		)	(8,295		)
End of period	$	31,579		$	37,184

11

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Under the terms of the VPP, SWR conveyed to a third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production. As of September 30, 2013, we have a remaining obligation to deliver approximately 514,000 BOE.

8. Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 5,000 shares of Common Stock.  As of September 30, 2013, the options had a weighted average exercise price of $32.21 per share (ranging from $22.90 per share to $41.74 per share), a weighted average remaining contractual term of 2.3 years, and an aggregate intrinsic value of $101,310 (based on a market price at September 30, 2013 of $52.47 per share).  No options were granted during the nine months ended September 30, 2013 or 2012.

Non-Equity Award Plans

The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs.  The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, by the participants.  The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (“APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas.  Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”).  At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships.  Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan.  We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements.  Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.

The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations.  The wells subject to the APO Reward Plan are not included in the APO Incentive Plan.  Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan.  Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area.  Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan.  To date, we have granted awards under the APO Reward Plan in 17 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each award, which dates range from January 1, 2007 to May 1, 2013.  Of these 17 awards, one award fully vested on November 4, 2011, three awards fully vested on August 9, 2012, three awards fully vested on May 5, 2013, six awards fully vested on June 1, 2013, two will fully vest on May 1, 2015 and two will fully vest on August 1, 2015.

In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the after-payout cash flow from a 22.5% working interest in one well.  As of October 25, 2011, the plan was fully vested and 100% of subsequent quarterly bonus amounts are payable to participants.

To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award.  The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.

We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years. Compensation expense (credit) related to non-equity award plans for the three months ended September 30, 2013 and 2012 and for the nine months ended September 30, 2013 and 2012 were $1.2 million, ($2.2) million, ($5.9) million and $2.2 million, respectively. Credits to expense resulted from the

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

reversal of previously accrued compensation expense attributable to a combination of actual payments of accrued compensation and changes in estimates of future compensation expense.

Aggregate compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:

	September 30, 2013		December 31, 2012
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	3,262	$	2,220
Non-current liabilities:
Accrued compensation under non-equity award plans	13,121		20,058
Total accrued compensation under non-equity award plans	$	16,383	$	22,278

9. Derivatives

Commodity Derivatives

From time to time, we utilize commodity derivatives in the form of swap contracts to attempt to optimize the price received for our oil and gas production.  Under swap contracts, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  Commodity derivatives are settled monthly as the contract production periods mature.

In October 2013, we entered into swap agreements with a counterparty covering 1 million barrels of our 2014 oil production at a price of $96.10 per barrel. 

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2013.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil			Gas
	Bbls	Price		MMBtu (a)	Price
Production Period:
4th Quarter 2013	300,000	$	104.60	330,000	$	3.34
2014	1,600,000	$	97.30	—	$	—
	1,900,000			330,000

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  As of September 30, 2013, a $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $1 million.

Accounting For Derivatives

We did not designate any of our currently open commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of September 30, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	2,139	Current	$	—
	Non-current	1,038		Non-current	—
Total		$	3,177		$	—

	Fair Value of Derivative Instruments as of December 31, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	7,495	Current	$	—
	Non-current	4,236		Non-current	—
Total		$	11,731		$	—

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	September 30, 2013
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	3,286		$	109
Effects of netting arrangements	(109		)	(109		)
Fair value of derivatives — net presentation	$	3,177		$	—

	December 31, 2012
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	17,851		$	6,120
Effects of netting arrangements	(6,120		)	(6,120		)
Fair value of derivatives — net presentation	$	11,731		$	—

All of our derivative contracts are with JPMorgan Chase Bank, N.A.  We have elected to net the outstanding positions with this counterparty between current and noncurrent assets or liabilities since we have the right to settle these positions on a net basis.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss)

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended									Nine Months Ended
Location of Gain or (Loss)	September 30, 2013									September 30, 2013
Recognized in Earnings	Realized			Unrealized			Total			Realized			Unrealized			Total
				(In thousands)									(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	(455	)	$	(7,823	)	$	(8,278	)	$	(1,364	)	$	(8,555	)	$	(9,919	)
Total	$	(455	)	$	(7,823	)	$	(8,278	)	$	(1,364	)	$	(8,555	)	$	(9,919	)

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended									Nine Months Ended
Location of Gain or (Loss)	September 30, 2012									September 30, 2012
Recognized in Earnings	Realized			Unrealized			Total			Realized			Unrealized		Total
				(In thousands)									(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	(1,390	)	$	(20,511	)	$	(21,901	)	$	(4,961	)	$	14,817	$	9,856
Total	$	(1,390	)	$	(20,511	)	$	(21,901	)	$	(4,961	)	$	14,817	$	9,856

10. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments.  Indebtedness under our revolving credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.

Fair Value Measurements

We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.  We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value.

Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:

Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The financial assets and liabilities measured on a recurring basis at September 30, 2013 and December 31, 2012 were commodity derivatives.  The fair value of all derivative contracts is reflected on the consolidated balance sheet as detailed in the following schedule:

	September 30, 2013		December 31, 2012
	Significant Other
	Observable Inputs
Description	(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	3,177	$	11,731
Total assets	$	3,177	$	11,731
Liabilities:
Fair value of commodity derivatives	$	—	$	—
Total liabilities	$	—	$	—

Fair Value of Other Financial Instruments

We estimate the fair value of our 2019 Senior Notes using quoted market prices (Level 1 inputs). Fair value is compared to the carrying value in the table below:

	September 30, 2013				December 31, 2012
	Carrying		Estimated		Carrying		Estimated
Description	Amount		Fair Value		Amount		Fair Value
	(In thousands)
7.75% Senior Notes due 2019	$	349,625	$	348,250	$	349,585	$	348,700

11. Income Taxes

Our effective federal and state income tax rate for the nine months ended September 30, 2013 of 37.4% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

We file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions.  Our tax returns for fiscal years after 2009 currently remain subject to examination by appropriate taxing authorities.  None of our income tax returns are under examination at this time.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Other Operating Revenues and Expenses

Net other operating revenues and expenses for the three months and nine months ended September 30, 2013 and September 30, 2012 are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In thousands)				(In thousands)
Other operating revenues:
Gain on sales of assets	$	1,971	$	106	$	2,738	$	543
Net marketing revenue	—		—		1,795		—
Total other operating revenues	$	1,971	$	106	$	4,533	$	543
Other operating expenses:
Loss on sales of assets	$	39	$	38	$	1,084	$	38
Net marketing expense	302		—		658		—
Impairment of inventory	122		169		127		447
Total other operating expenses	$	463	$	207	$	1,869	$	485

We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities.  Inventory is carried at the lower of average cost or estimated fair market value.  We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards.  To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment.  We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory.  If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.

13. Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012.  Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea is carried at cost of $11 million.  As of September 30, 2013, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

14. Costs of Oil and Gas Properties

The following sets forth the net capitalized costs for oil and gas properties as of September 30, 2013 and December 31, 2012.

	September 30, 2013			December 31, 2012
	(In thousands)
Proved properties	$	2,267,590		$	2,482,185
Unproved properties	96,527			88,618
Total capitalized costs	2,364,117			2,570,803
Accumulated depletion	(1,244,965		)	(1,234,626		)
Net capitalized costs	$	1,119,152		$	1,336,177

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.Commitments and Contingencies

Legal Proceedings

SWR is a defendant in a suit in Union County, Arkansas where the plaintiffs are suing for the costs of remediation to a lease on which operations were commenced in the 1930's. The plaintiffs are seeking in excess of $8 million. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $750,000, of which SWR would pay $710,000. To accomplish the settlement, the case would be converted to a class action, and each member of the class would be offered the right to either participate or opt out of the class and continue a separate action for damages. If more than 25% of the plaintiffs opt out of the settlement, SWR will have the right to terminate the settlement. Any plaintiffs opting out would be subject to all previous rulings of the court, including an order dismissing a significant number of plaintiffs' claims on the basis that such claims were time barred. SWR believes that the judge will approve the settlement and the number of plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $710,000 for the nine months endedSeptember 30, 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.

We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

16. Impairment of Property and Equipment

We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value.  The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset.  We categorize the measurement of fair value of these assets as Level 3 inputs.  We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: discounted cash flow method, flowing daily production method and proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances.  We recorded a provision for impairment of proved properties of $709,000 for the three months ended September 30, 2013, and there were no provisions for impairment of proved properties for the three months ended September 30, 2012.  We recorded a provision for impairment of proved properties of $89.8 million for the nine months ended September 30, 2013 and $5.7 million for the nine months ended September 30, 2012. The impairment for the three months ended September 30, 2013 was related to the write down of certain non-core Permian Basin properties to their estimated fair value. The impairment for the nine months ended September 30, 2013 was related to the write down of our Andrews County Wolfberry assets and certain non-core Permian Basin properties to their estimated fair value. The impairments for the nine months ended September 30, 2012 related to non-core areas in the Permian Basin to reduce the carrying values of those properties to their estimated fair value.

Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value. We categorize the measurement of fair value of unproved properties as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $568,000 for the three months ended September 30, 2013 and $187,000 for the three months ended September 30, 2012, and $944,000 for the nine months ended September 30, 2013 and $711,000 for the nine months ended September 30, 2012, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Segment Information

We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services.

The following tables present selected financial information regarding our operating segments for the three months and nine months ended September 30, 2013 and 2012:

For the Three Months Ended
September 30, 2013
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	107,121		$	9,021		$	(4,977	)	$	111,165
Depreciation, depletion and amortization (a)	32,941			3,340			(644		)	35,637
Other operating expenses (b)	38,289			7,144			(3,823		)	41,610
Interest expense	9,262			—			—			9,262
Other (income) expense	7,804			—			—			7,804
Income (loss) before income taxes	18,825			(1,463		)	(510		)	16,852
Income tax (expense) benefit	(6,414		)	513			—			(5,901		)
Net income (loss)	$	12,411		$	(950	)	$	(510	)	$	10,951
Total assets	$	1,352,645		$	54,524		$	(27,459	)	$	1,379,710
Additions to property and equipment	$	64,775		$	1,494		$	(510	)	$	65,759

For the Nine Months Ended
September 30, 2013
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	304,052		$	26,660		$	(13,764	)	$	316,948
Depreciation, depletion and amortization (a)	190,813			10,728			(1,867		)	199,674
Other operating expenses (b)	116,319			24,705			(11,788		)	129,236
Interest expense	30,106			—			—			30,106
Other (income) expense	7,912			—			—			7,912
Income (loss) before income taxes	(41,098		)	(8,773		)	(109		)	(49,980		)
Income tax (expense) benefit	15,622			3,071			—			18,693
Net income (loss)	$	(25,476	)	$	(5,702	)	$	(109	)	$	(31,287	)
Total assets	$	1,352,645		$	54,524		$	(27,459	)	$	1,379,710
Additions to property and equipment	$	200,949		$	3,097		$	(109	)	$	203,937

19

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the Three Months Ended
September 30, 2012
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	102,415		$	14,869		$	(9,521	)	$	107,763
Depreciation, depletion and amortization (a)	35,580			3,666			(1,585		)	37,661
Other operating expenses (b)	43,117			13,169			(7,757		)	48,529
Interest expense	9,786			—			—			9,786
Other (income) expense	22,463			(3		)	—			22,460
Income (loss) before income taxes	(8,531		)	(1,963		)	(179		)	(10,673		)
Income tax (expense) benefit	2,810			687			—			3,497
Net income (loss)	$	(5,721	)	$	(1,276	)	$	(179	)	$	(7,176	)
Total assets	$	1,504,338		$	63,731		$	(21,530	)	$	1,546,539
Additions to property and equipment	$	107,178		$	3,023		$	(179	)	$	110,022

For the Nine Months Ended
September 30, 2012
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	309,964		$	46,134		$	(34,656	)	$	321,442
Depreciation, depletion and amortization (a)	104,416			10,703			(5,922		)	109,197
Other operating expenses (b)	130,668			40,963			(28,591		)	143,040
Interest expense	27,817			—			—			27,817
Other (income) expense	(10,592		)	(3		)	—			(10,595		)
Income (loss) before income taxes	57,655			(5,529		)	(143		)	51,983
Income tax (expense) benefit	(20,493		)	1,935			—			(18,558		)
Net income (loss)	$	37,162		$	(3,594	)	$	(143	)	$	33,425
Total assets	$	1,504,338		$	63,731		$	(21,530	)	$	1,546,539
Additions to property and equipment	$	419,094		$	12,614		$	(143	)	$	431,565

(a) Includes impairment of property and equipment.

(b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of asset retirement obligations, general and administrative and other operating expenses.

20

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Guarantor Financial Information

In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes (see Note 3).  Presented below is condensed consolidated financial information of CWEI (“Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013, all of the Issuer's wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 18.

The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated.

Condensed Consolidating Balance Sheet September 30, 2013 (Unaudited) (Dollars in thousands)
	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Current assets	$	148,083	$	226,845	$	2,099	$	(220,306	)	$	156,721
Property and equipment, net	828,932		355,721		12,826		—			1,197,479
Investments in subsidiaries	333,243		—		—		(333,243		)	—
Fair value of derivatives	1,038		—		—		—			1,038
Other assets	11,073		13,399		—		—			24,472
Total assets	$	1,322,369	$	595,965	$	14,925	$	(553,549	)	$	1,379,710
Current liabilities	$	252,565	$	88,084	$	2,177	$	(217,528	)	$	125,298
Non-current liabilities:
Long-term debt	672,625		—		—		—			672,625
Deferred income taxes	122,141		125,114		544		(108,597		)	139,202
Other	33,528		61,611		117		—			95,256
	828,294		186,725		661		(108,597		)	907,083
Equity	241,510		321,156		12,087		(227,424		)	347,329
Total liabilities and equity	$	1,322,369	$	595,965	$	14,925	$	(553,549	)	$	1,379,710

21

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet December 31, 2012 (Dollars in thousands)
	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Current assets	$	133,080	$	224,210	$	—	$	(232,820	)	$	124,470
Property and equipment, net	1,053,453		366,905		—		—			1,420,358
Investments in subsidiaries	305,899		—		—		(305,899		)	—
Fair value of derivatives	4,236		—		—		—			4,236
Other assets	12,112		13,408		—		—			25,520
Total assets	$	1,508,780	$	604,523	$	—	$	(538,719	)	$	1,574,584
Current liabilities	$	241,200	$	112,534	$	—	$	(232,820	)	$	120,914
Non-current liabilities:
Long-term debt	809,585		—		—		—			809,585
Deferred income taxes	143,699		117,950		—		(105,819		)	155,830
Other	41,499		68,140		—		—			109,639
	994,783		186,090		—		(105,819		)	1,075,054
Equity	272,797		305,899		—		(200,080		)	378,616
Total liabilities and equity	$	1,508,780	$	604,523	$	—	$	(538,719	)	$	1,574,584

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2013 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	71,943		$	38,470		$	752		$	—		$	111,165
Costs and expenses	51,320			25,598			329			—			77,247
Operating income (loss)	20,623			12,872			423			—			33,918
Other income (expense)	(17,372		)	(13		)	319			—			(17,066		)
Equity in earnings of subsidiaries	8,841			—			—			(8,841		)	—
Income tax (expense) benefit	(1,141		)	(4,500		)	(260		)	—			(5,901		)
Net income (loss)	$	10,951		$	8,359		$	482		$	(8,841	)	$	10,951

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2013 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	209,313		$	106,173		$	1,462		$	—		$	316,948
Costs and expenses	243,005			85,218			687			—			328,910
Operating income (loss)	(33,692		)	20,955			775			—			(11,962		)
Other income (expense)	(37,962		)	(483		)	427			—			(38,018		)
Equity in earnings of subsidiaries	14,088			—			—			(14,088		)	—
Income tax (expense) benefit	26,279			(7,165		)	(421		)	—			18,693
Net income (loss)	$	(31,287	)	$	13,307		$	781		$	(14,088	)	$	(31,287	)

22

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Total revenue	$	74,129		$	34,065		$	—	$	(431	)	$	107,763
Costs and expenses	57,952			28,669			—		(431		)	86,190
Operating income (loss)	16,177			5,396			—		—			21,573
Other income (expense)	(32,431		)	185			—		—			(32,246		)
Equity in earnings of subsidiaries	3,628			—			—		(3,628		)	—
Income tax (expense) benefit	5,450			(1,953		)	—		—			3,497
Net income (loss)	$	(7,176	)	$	3,628		$	—	$	(3,628	)	$	(7,176	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Total revenue	$	222,570		$	99,896		$	—	$	(1,024	)	$	321,442
Costs and expenses	166,584			86,677			—		(1,024		)	252,237
Operating income (loss)	55,986			13,219			—		—			69,205
Other income (expense)	(19,672		)	2,450			—		—			(17,222		)
Equity in earnings of subsidiaries	10,185			—			—		(10,185		)	—
Income tax (expense) benefit	(13,074		)	(5,484		)	—		—			(18,558		)
Net income (loss)	$	33,425		$	10,185		$	—	$	(10,185	)	$	33,425

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2013 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	85,851		$	64,905		$	1,258		$	1,867		$	153,881
Investing activities	24,790			(25,837		)	(1,484		)	(1,867		)	(4,398		)
Financing activities	(100,050		)	(37,406		)	456			—			(137,000		)
Net increase (decrease) in cash and cash equivalents	10,591			1,662			230			—			12,483
Cash at beginning of period	6,030			4,696			—			—			10,726
Cash at end of period	$	16,621		$	6,358		$	230		$	—		$	23,209

23

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Operating activities	$	78,864		$	73,097		$	—	$	5,922		$	157,883
Investing activities	(359,332		)	(27,460		)	—		(5,922		)	(392,714		)
Financing activities	286,360			(46,360		)	—		—			240,000
Net increase (decrease) in cash and cash equivalents	5,892			(723		)	—		—			5,169
Cash at beginning of period	12,853			4,672			—		—			17,525
Cash at end of period	$	18,745		$	3,949		$	—	$	—		$	22,694

19. Subsequent Events

Effective October 1, 2013, we issued an additional $250 million of aggregate principal amount of our 2019 Senior Notes. These notes and the 2019 Senior Notes issued in March and April 2011 are treated as a single class of debt securities under the same indenture. The net proceeds from the offering were used to repay borrowings under our revolving credit facility (see Note 3).

As of October 15, 2013, the buyer of our Andrews County Wolfberry Assets, has exercised its right to extend the post-closing cure deadline an additional 180 days related to the remaining escrow balance of $25.9 million pending resolution of certain title requirements (see Note 5).

In October 2013, we entered into swap agreements with a counterparty covering 1 million barrels of our 2014 oil production at a price of $96.10 per barrel (see Note 9). 

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 2013 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

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Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2012.  Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.

Forward-Looking Statements

The information in this Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should, could or may occur in the future are forward-looking statements.  These forward-looking statements are based on management’s current expectations and belief, based on currently available information, as to the outcome and timing of future events and their effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2012 and in this Form 10-Q.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

• estimates of our oil and gas reserves;

• estimates of our future oil and gas production, including estimates of any increases or decreases in production;

• planned capital expenditures and the availability of capital resources to fund those expenditures;

• our outlook on oil and gas prices;

• our outlook on domestic and worldwide economic conditions;

• our access to capital and our anticipated liquidity;

• our future business strategy and other plans and objectives for future operations;

• the impact of political and regulatory developments;

• our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;

• estimates of the impact of new accounting pronouncements on earnings in future periods; and

• our future financial condition or results of operations and our future revenues and expenses.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production and marketing of oil and gas.  These risks include, but are not limited to:

• the possibility of unsuccessful exploration and development drilling activities;

• our ability to replace and sustain production;

• commodity price volatility;

• domestic and worldwide economic conditions;

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• the availability of capital on economic terms to fund our capital expenditures and acquisitions;

• our level of indebtedness;

• the impact of the past or future economic recessions on our business operations, financial condition and ability to raise capital;

• declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our revolving credit facility and impairments;

• the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

• the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;

• drilling and other operating risks;

• hurricanes and other weather conditions;

• lack of availability of goods and services;

• regulatory and environmental risks associated with drilling and production activities;

• the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and

• the other risks described in our Form 10-K for the year ended December 31, 2012 and in this Form 10-Q.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.  The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.  If significant, these revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

As previously discussed, should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended December 31, 2012 and in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety after the date made, whether as a result of new information, future events or otherwise, except as required by law.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities.  One core area of the Permian Basin is our Bone Springs/Wolfcamp play (“Wolfbone”) located in the Delaware Basin on the western edge of the Permian Basin.  We are also continuing to exploit Eagle Ford Shale drilling opportunities on our extensive acreage position in the Giddings Area of East Central Texas. During the nine months ended September 30, 2013, we spent $197.6 million on exploration and development activities.

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Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2013 and the outlook for the remainder of 2013.

• In April 2013, we sold 95% of our Wolfberry oil and gas reserves, leasehold interests and facilities located in Andrews County, Texas for $215.2 million, subject to customary closing adjustments, with $25.9 million remaining in escrow pending resolution of certain title requirements that we believe will be cured. As a result, reported oil and gas production, revenues and operating costs for the quarter and nine months ended September 30, 2013 are not comparable to reported amounts for periods in 2012.

• Our oil and gas sales, excluding amortized deferred revenues, increased $2.7 million, or 3%, from the third quarter2012.  Price variances accounted for a $13.3 million increase and production variances accounted for a $10.6 million decrease. Average realized oil prices were $103.75 per barrel in the third quarter of 2013 versus $89.48 per barrel in the third quarter 2012, and average realized gas prices were $3.49 per Mcf in 2013 versus $3.29 per Mcf in 2012. In addition, oil and gas sales for the third quarter of 2013 includes $2.2 million of amortized deferred revenue attributable to the volumetric production payment (“VPP”) versus $2.5 million for the third quarter of 2012. Reported production and related average realized sales prices exclude volumes associated with the VPP.

• Our oil, gas and natural gas liquids (“NGL”) production per barrel of oil equivalent (“BOE”) declined 12% compared to the third quarter2012, with oil production decreasing 10% to 9,674 barrels per day, gas production decreasing 24% to 16,598 Mcf per day and NGL production increasing 9% to 1,359 barrels per day. Oil and NGL production accounted for approximately 80% of our total BOE production in the third quarter of 2013 versus 77% in the third quarter of 2012. Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible, resulting in a reduction in natural gas volumes and an increase in extracted NGL volumes. Periods for 2012 have not been adjusted to conform to the 2013 presentation.

• After giving effect to the Andrews sale discussed above, oil and gas production on a BOE basis increased 4% for the third quarter of 2013 as compared to the third quarter of 2012, with oil production increasing 587 barrels per day, gas production decreasing 3,511 Mcf per day and NGL production increasing 500 barrels per day.

• Production costs decreased 21% or $6.9 million for the third quarter of 2013 compared to the third quarter of 2012. After giving effect to the Andrews sale, production costs declined $1.8 million, or 6%, due primarily to lower salt water disposal costs and other cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.

• We recorded an $8.3 million net loss on derivatives in the third quarter of 2013, consisting of a $7.8 million unrealized loss for changes in mark-to-market valuations and a $455,000 realized loss on settled contracts.  For the same period in 2012, we recorded a $21.9 million net loss on derivatives, consisting of a $20.5 million unrealized loss for changes in mark-to-market valuations and a $1.4 million realized loss on settled contracts.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

• General and administrative (“G&A”) expenses were $10 million in the third quarter of 2013 compared to $5.8 million in the third quarter of 2012.  G&A expenses in the third quarter of 2012 related to accrued compensation expense from our APO reward plans included a non-cash reversal of previously accrued compensation expense totaling $2.2 million as compared to a charge of $1.2 million in the third quarter of 2013.

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Recent Exploration and Development Activities

Overview

Since the second quarter of 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Giddings Area.  We spent $197.6 million during the nine month period ended September 30, 2013 on exploration and development activities and currently plan to spend approximately $72.4 million on similar activities for the remainder of 2013.  Our actual expenditures during 2013 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year.  Factors such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2013.

Core Areas

Permian Basin

The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period.  The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet.  The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential.  Although many fields in the Permian Basin have been heavily exploited in the past, higher oil prices and improved technology (including deep horizontal drilling) continue to attract high levels of drilling and recompletion activities.  We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc.  This acquisition provided us with an inventory of potential drilling and recompletion activities.

We spent $100.2 million in the Permian Basin during the nine month period ended September 30, 2013 on drilling and completion activities and $9.1 million on leasing and seismic activities.  We drilled and completed 33 gross (23.7 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the nine month period ended September 30, 2013.  We currently plan to spend approximately $47.7 million on drilling and leasing activities in this area during the remainder of 2013.  Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 91,000 net acres in the active Wolfbone resource play in the Delaware Basin in Reeves, Loving, Ward and Winkler Counties, Texas and may earn up to 10,000 additional acres through future drilling commitments under an existing farm-in arrangement. A Wolfbone well is a well that commingles production from the Bone Springs and Wolfcamp formations which are typically encountered at depths of 8,000 to 13,000 feet.  These Permian aged formations in the Delaware Basin are composed of limestone and sandstone. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals. To date, we have focused on the over-pressured intervals, having drilled 90 wells in the area: 70 vertical Wolfbone wells and 20 horizontal wells targeting multiple Bone Springs/Wolfcamp intervals.

A significant portion of our current and future holdings in this area are associated with a farm-in agreement we entered into in March 2011 with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of five years.  Chesapeake's position in the agreement is now held by Shell Exploration and Production (“Shell”). For each well that we drill in the farm-in area that meets certain specified requirements (each, a “carried well”), Shell, or its successors to this agreement, will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area.  Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells each year during the term of the agreement to a maximum of 100 carried wells.  Excess wells drilled during any year may be applied towards our drilling obligations in the next year.  To date, we have been credited for 45 carried wells under this agreement.

 We own oil, gas and water disposal pipelines in Reeves County, consisting of 71 miles of oil pipelines with a design capacity of 18,000 barrels of oil per day, 70 miles of gas pipelines with a design capacity of 25,000 Mcf of natural gas per day and 65 miles of salt water disposal pipelines with a design capacity of 20,000 barrels of produced water per day.  These facilities may be expanded to accommodate new wells as we continue our development in the area.

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We spent approximately $67.8 million on drilling and completion activities and $8.2 million for leasing activities in the Wolfbone play during the nine month period ended September 30, 2013.  We plan to spend approximately $42.4 million on similar drilling and leasing activities in the Wolfbone play for the remainder of 2013. 

We currently plan to utilize three rigs in this area during the remainder of 2013.

East Permian Basin

We have approximately 36,000 net acres in the emerging Cline Shale play in Glasscock and Sterling Counties which was originally leased as a Wolfberry prospect. In 2012, we drilled a horizontal Cline Shale well. Although results from this well were disappointing, we believe that intervening operational factors may have contributed to the lower than anticipated production performance to date. We spent $6.4 million in the East Permian Basin during the nine month period ended September 30, 2013 on drilling and leasing activities primarily on non-operated wells. 

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area.  Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.  Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale, and Taylor formations. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

Most of our existing production in the Giddings Area is derived from the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana.  The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet.  Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple zones.  Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.

Eagle Ford Shale

The Eagle Ford Shale formation lies immediately beneath the Austin Chalk formation where we have approximately 177,000 net acres in production.  We believe that more than 100,000 net acres in this area may also be prospective for economic Eagle Ford Shale production.  Since July 2011, we have drilled 12 horizontal Eagle Ford Shale wells.  Each of these wells has been or will be completed by multi-stage hydraulic fracturing processes using about five million pounds of proppant and 100,000 barrels of water.  We are currently using one of our drilling rigs in the Giddings Area to drill horizontal wells in the Eagle Ford Shale formation. During the nine month period ended September 30, 2013, we spent approximately $50.3 million on drilling and completion activities and $22.4 million for leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $22.7 million on similar drilling and leasing activities in this area during the remainder of 2013. 

Other

We spent $15.6 million during the nine months ended September 30, 2013 on exploration and development activities in other regions, including South Louisiana, Oklahoma and California and we currently plan to spend $2 million for the remainder of 2013.

South Louisiana

During the first quarter of 2013, we completed the Christian #1, an exploratory well in Jefferson Parish. During the second quarter we drilled the Macon Stringer Heirs #1, an exploratory well in Terrebone Parish, resulting in a dry hole. During the nine month period ended September 30, 2013, we spent $6.5 million on drilling and leasing activities in South Louisiana.

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Oklahoma

We began drilling operations in 2013 on certain exploratory prospects in Oklahoma. These prospects were generated over the past two years using data obtained through proprietary 3D seismic shoots and target multiple conventional oil-prone formations encountered above a vertical depth of 6,000 feet. To date, we have drilled three exploratory wells, resulting in dry holes and have completed two development wells as producers. We are currently waiting on completion of the Brown 1-26 and the Mosetta 1-7. During the nine month period ended September 30, 2013, we spent $5.6 million on seismic, leasing and drilling activities in this area and we currently plan to spend approximately $1.4 million on similar drilling and leasing activities during the remainder of 2013.

California

We plan to begin limited drilling operations in 2014 on a 1,300 acre lease acquired from the city of Whittier. Based on production history from more than 400 wells in the area, we are targeting multiple oil-bearing Miocene sands first encountered at depths above 1,500 feet which we plan to directionally drill in order to maximize exposure to each target sand. We own a 70% working interest in the lease. During the nine month period ended September 30, 2013, we spent $1.8 million on leasing activities in this area.

Pipelines and Other Midstream Facilities

We own an interest in and operate oil, natural gas and water service facilities in the states of Texas and Louisiana. These midstream facilities consist of interests in approximately 314 miles of pipeline, four treating plants, one dehydration facility, and seven wellhead type treating and/or compression stations.  Most of our operated gas gathering and treating activities facilitate the transportation and marketing of our operated oil and gas production.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we operate 14 drilling rigs, 12 of which we own, and two of which we lease under long-term contracts.  We believe that owning and operating our own rigs helps control our cost structure while providing us flexibility to take advantage of drilling opportunities on a timely basis.  The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties.  As of October 29, 2013, we were using seven of our rigs to drill wells in our developmental drilling programs, one rig was working for a third party and the remaining six rigs were idle. 

Known Trends and Uncertainties

We have an extensive acreage position within the Permian Basin and Giddings Area with a large portion of that acreage currently held by production that will require significant capital to fully develop.  Through asset sales and joint venture arrangements, we expect to achieve a sustainable balance between our future drilling commitments and our anticipated financial resources.  We are unable to give assurance that our drilling results, or the term of any sale or joint venture arrangement would be acceptable to us or provide sufficient capital to meet future drilling commitments.

Our developmental drilling programs are very sensitive to oil prices and drilling costs.  We attempt to control costs through drilling efficiencies by the use of our own rigs, purchasing casing and tubing at periods when we believe prices are suitable and working with service providers to receive acceptable unit costs.  We plan to continue these programs as long as oil prices remain favorable.  In order to continue drilling in these areas, we must be able to realize an acceptable margin between our expected cash flow from new production and our cost to drill and complete new wells.  If any combination of falling oil prices and rising costs of drilling, completion and other field services occur in future periods, we may discontinue a program until margins return to acceptable levels.

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Supplemental Information

The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-Q with data that is not readily available from those statements.

	Three Months Ended September 30,
	2013			2012
Oil and Gas Production Data:
Oil (MBbls)	890			993
Gas (MMcf)	1,527			2,010
Natural gas liquids (MBbls)	125			115
Total (MBOE)	1,270			1,443
Average Realized Prices (a) (b):
Oil ($/Bbl)	$	103.75		$	89.48
Gas ($/Mcf)	$	3.49		$	3.29
Natural gas liquids ($/Bbl)	$	33.47		$	31.37
Loss on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(367	)	$	(1,390	)
Per unit produced ($/Bbl)	$	(0.41	)	$	(1.40	)
Gas: Net realized loss	$	(88	)	$	—
Per unit produced ($/Mcf)	$	(0.06	)	$	—
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	1,934			2,018
Other	3,476			5,247
Austin Chalk/Eagle Ford Shale	3,889			3,199
Other(c)	375			329
Total	9,674			10,793
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	1,695			1,449
Other (c) (d)	7,569			12,246
Austin Chalk/Eagle Ford Shale	2,051			1,793
Other	5,283			6,360
Total	16,598			21,848
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	348			257
Other (c) (d)	718			711
Austin Chalk/Eagle Ford Shale	274			232
Other	19			50
Total	1,359			1,250
(Continued)

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	Three Months Ended September 30,
	2013		2012
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	—	$	32
Permian Basin	39		53
Deep Bossier	—		111
Other	570		110
Total	609		306
Seismic and other	177		2,710
Total exploration costs	$	786	$	3,016
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	31,641	$	35,145
Contract drilling depreciation	2,696		2,082
Other depreciation	591		434
Total depreciation, depletion, and amortization	$	34,928	$	37,661
Oil and Gas Costs ($/BOE Produced):
Production costs	$	20.20	$	22.57
Production costs (excluding production taxes)	$	15.98	$	18.99
Oil and gas depletion	$	24.91	$	24.36
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	8,826	$	8,024
Non-cash employee compensation (e)	1,204		(2,194		)
Total	$	10,030	$	5,830
Net Wells Drilled (f):
Exploratory Wells	1.2		0.5
Developmental Wells	14.1		23.9

	Nine Months Ended September 30,
	2013			2012
Oil and Gas Production Data:
Oil (MBbls)	2,695			2,889
Gas (MMcf)	4,753			6,154
Natural gas liquids (MBbls)	399			304
Total (MBOE)	3,886			4,219
Average Realized Prices (a) (b):
Oil ($/Bbl)	$	96.16		$	92.62
Gas ($/Mcf)	$	3.56		$	3.46
Natural gas liquids ($/Bbl)	$	32.44		$	40.05
Loss on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(981	)	$	(4,961	)
Per unit produced ($/Bbl)	$	(0.36	)	$	(1.72	)
Gas: Net realized loss	$	(383	)	$	—
Per unit produced ($/Mcf)	$	(0.08	)	$	—
(Continued)

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	Nine Months Ended September 30,
	2013		2012
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	1,886		1,575
Other(c)	3,983		5,473
Austin Chalk/Eagle Ford Shale	3,708		3,115
Other	295		378
Total	9,872		10,541
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	1,582		780
Other (c) (d)	8,229		12,797
Austin Chalk/Eagle Ford Shale	2,113		1,997
Other	5,486		6,881
Total	17,410		22,455
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	299		117
Other (c) (d)	905		687
Austin Chalk/Eagle Ford Shale	240		241
Other	18		63
Total	1,462		1,108
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	1,000	$	344
Permian Basin	43		349
Deep Bossier	—		1,322
Other	1,937		277
Total	2,980		2,292
Seismic and other	3,541		5,445
Total exploration costs	$	6,521	$	7,737
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	99,269	$	97,698
Contract drilling depreciation	8,861		4,781
Other depreciation	1,733		1,007
Total depreciation, depletion, and amortization	$	109,863	$	103,486
Oil and Gas Costs ($/BOE Produced):
Production costs	$	21.42	$	22.27
Production costs (excluding production taxes)	$	17.57	$	18.55
Oil and gas depletion	$	25.55	$	23.16
(Continued)

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	Nine Months Ended September 30,
	2013			2012
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	26,298		$	22,933
Non-cash employee compensation (e)	(5,897		)	2,200
Total	$	20,401		$	25,133
Net Wells Drilled (f):
Exploratory Wells	2.7			3.8
Developmental Wells	38.8			76.1
________

(a) Oil and gas sales includes $2.2 million for the three months ended September 30, 2013, $2.5 million for the three months ended September 30, 2012, $6.6 million for the nine months ended September 30, 2013, and $5.9 million for the nine months ended September 30, 2012 of amortized deferred revenue attributable to a volumetric production payment (“VPP”) transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 28,793 barrels of oil and 8,550 Mcf of gas for the three months ended September 30, 2013, 32,788 barrels of oil and 14,826 Mcf of gas for the three months ended September 30, 2012, 88,897 barrels of oil and 23,589 Mcf of gas for the nine months ended September 30, 2013 and 77,755 barrels of oil and 32,000 Mcf of gas for the nine months ended September 30, 2012 associated with the VPP.

(b) No derivatives were designated as cash flow hedges in the table above.  All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.

(c) In April 2013, we sold 95% of our interest in certain properties in Andrews County, Texas. The following is a summary of the average daily production related to the sold interest for periods prior to April 1, 2013.

	Three Months Ended September 30,	Nine Months Ended September 30,
	2012	2013	2012
Average Daily Production:
Oil (Bbls)	1,707	538	1,974
Natural gas (Mcf)	1,739	597	1,595
NGL (Bbls)	391	117	394
Total (Boe)	2,388	755	2,634

(d) Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during the three months and nine months ended September 30, 2012, we estimate that our reported natural gas volumes would have decreased by 2,200 Mcf/day and that our reported NGL volumes would have increased by 600 BOE/day during each of the 2012 periods.

(e) Non-cash employee compensation relates to our non-equity award plans.

(f) Excludes wells being drilled or completed at the end of each period.

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Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2013 to the comparative period in 2012.  Unless otherwise indicated, references to 2013 and 2012 within this section refer to the three months ended September 30, 2013 and 2012, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, increased $2.7 million, or 3% in 2013, from 2012.  Price variances accounted for a $13.3 million increase, and production variances accounted for a $10.6 million decrease.  Oil and gas sales in 2013 also include $2.2 million of amortized deferred revenue versus $2.5 million in 2012 attributable to a VPP.  Combined oil, gas and NGL production in 2013 (on a BOE basis) declined 12% compared to 2012.  Our production mix increased from 77% oil and NGL in 2012 to approximately 80% in 2013. Oil production decreased 10% in 2013 from 2012. NGL production increased 9% while gas production decreased 24% in 2013 from 2012.  Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during 2012, we estimate that our natural gas volumes would have decreased by approximately 2,200 Mcf per day related to plant shrinkage and that NGL volumes would have increased by approximately 600 BOE per day. Periods for 2012 have not been adjusted to conform to the 2013 presentation. In 2013, our realized oil price was 16% higher than 2012, and our realized gas price was 6% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 21% to $25.7 million in 2013 as compared to $32.6 million in 2012.  After giving effect to the Andrews sale, production costs declined $1.8 million, or 6%, due primarily to lower salt water disposal costs and other cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.

Oil and gas depletion expense decreased $3.5 million from 2012 to 2013 due to a $4.2 million decrease related to production variances and a $708,000 increase due to rate variances.  On a BOE basis, depletion expense increased 2% to $24.91 per BOE in 2013 from $24.36 per BOE in 2012.  Most of the decrease in depletion expense related to a decrease in production related to the sale of our Andrews County assets offset by an increase in production in the Giddings area and increases in rate variances in the Wolfbone area. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

We recorded a provision for impairment of property and equipment of $709,000 in 2013 and none in 2012. The 2013 impairment was to write down the carrying value of certain non-core Permian Basin properties to their estimated fair value. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value.

Exploration costs

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2013, we charged to expense $786,000 of exploration costs, as compared to $3 million in 2012.

Contract Drilling Services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities.  Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss).  Drilling rig services revenue related to external customers was $4 million in 2013 compared to $5.3 million in 2012. Drilling service costs related to external customers and idle rig charges were $3.2 million in 2013 and $5.3 million in 2012. Contract drilling depreciation for 2013 was $2.7 million compared to $2.1 million in 2012.

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General and Administrative

G&A expenses increased $4.2 million from $5.8 million in 2012 to $10 million in 2013.  G&A expenses for the three months ended September 30, 2012 related to accrued compensation expense from our APO reward plans included a non-cash reversal of previously accrued compensation expense of $2.2 million as compared to a charge of $1.2 million for the three months ended September 30, 2013.  Credits to employee compensation expense from incentive compensation plans result from reversals of previously accrued compensation expense due to a combination of actual payments to plan participants and changes in estimated future compensation expense based on commodity prices and production forecasts.

Gain/loss on derivatives

We did not designate any derivative contracts in 2013 or 2012 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For the three months ended September 30, 2013, we reported an $8.3 million net loss on derivatives, consisting of a $7.8 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2013 and a $455,000 realized loss on settled contracts.  For the three months ended September 30, 2012, we reported a $21.9 million net loss on derivatives, consisting of a $20.5 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2012 and a $1.4 million realized loss on settled contracts.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $1.8 million on sales of assets and impairment of inventory in 2013 compared to a net loss of $101,000 in 2012.  The 2013 gain related primarily to the sale of our Wash McAdams properties in Walker County, Texas.  The 2012 loss related primarily to the write-down of inventory to its estimated market value at September 30, 2012. Gain on sales of assets is included in other operating revenues and loss on sales of assets and impairment of inventory is included in other operating expenses in our consolidated statements of operations and comprehensive income (loss). 

Income taxes

Our estimated federal and state effective income tax rate in 2013 of 35% was equal to the statutory federal rate of 35%.

Operating Results — Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2013 to the comparative period in 2012.  Unless otherwise indicated, references to 2013 and 2012 within this section refer to the nine months ended September 30, 2013 and 2012, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $12.7 million, or 4% in 2013, from 2012.  Production variances accounted for a $19.7 million decrease and price variances accounted for a $7 million increase.  Oil and gas sales in 2013 also include $6.6 million of amortized deferred revenue versus $5.9 million in 2012 attributable to a VPP.  Combined oil, gas and NGL production in 2013 (on a BOE basis) declined 8% compared to 2012.  Our production mix increased from 76% oil and NGL in 2012 to approximately 80% in 2013. Oil production decreased 7% in 2013 from 2012. NGL production increased 31% while gas production decreased 23% in 2013 from 2012.  Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during 2012, we estimate that our natural gas volumes would have decreased by approximately 2,200 Mcf per day related to plant shrinkage and that our NGL volumes would have increased by approximately 600 BOE per day. Periods for 2012 have not been adjusted to conform to the 2013 presentation. In 2013, our realized oil price was 4% higher than 2012, and our realized gas price was 3% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 11% to $83.3 million in 2013 as compared to $93.9 million in 2012.  After giving effect to the Andrews sale, production costs increased $430,000, or 1%, due primarily to a combination of more producing wells and rising costs of field services, which was offset in part by cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.

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Oil and gas depletion expense increased $1.6 million from 2012 to 2013 due to a $9.3 million increase related to rate variances and a $7.7 million decrease due to production variances.  On a BOE basis, depletion expense increased 10% to $25.55 per BOE in 2013 from $23.16 per BOE in 2012.  Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

We recorded a provision for impairment of property and equipment of $89.8 million in 2013 and $5.7 million in 2012. The 2013 impairment was related to the write down of our Andrews County Wolfberry assets and certain non-core Permian Basin properties to their estimated fair value. The impairments for 2012 related to non-core areas in the Permian Basin to reduce the carrying values of those properties to their estimated fair value. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value.

Exploration costs

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2013, we charged to expense $6.5 million of exploration costs, as compared to $7.7 million in 2012.

Contract Drilling Services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities.  Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss).  Drilling rig services revenue related to external customers was $12.9 million in 2013 compared to $11.5 million in 2012. Drilling service costs related to external customers and idle rig charges were $12.7 million in 2013 compared to $12.2 million in 2012. Contract drilling depreciation for 2013 was $8.9 million compared to $4.8 million in 2012.

General and Administrative

G&A expenses decreased $4.7 million from $25.1 million in 2012 to $20.4 million in 2013.  Most of the decrease was attributable to non-cash reversals of previously accrued compensation expense from our APO reward plans in 2013. The 2013 credits to G&A expense were offset by cash payments to participants in plans associated with the Andrews County properties. Credits to employee compensation expense from incentive compensation plans result from reversals of previously accrued compensation expense due to a combination of actual payments to plan participants and changes in estimated future compensation expense based on commodity prices and production forecasts.

Gain/loss on derivatives

We did not designate any derivative contracts in 2013 or 2012 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For the nine months ended September 30, 2013, we reported a $9.9 million net loss on derivatives, consisting of an $8.5 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2013 and a $1.4 million realized loss on settled contracts.  For the nine months ended September 30, 2012, we reported a $9.9 million net gain on derivatives, consisting of a $14.8 million non-cash unrealized gain to mark our derivative positions to their fair value at September 30, 2012 and a $4.9 million realized loss on settled contracts.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $1.5 million on sales of assets and impairment of inventory in 2013 compared to a net gain of $58,000 in 2012.  The 2013 gain related primarily to the sale of our Andrews County, Texas properties and the Wash McAdams properties in Walker County, Texas.  Gain on sales of assets are included in other operating revenues and loss on sales of assets and impairment of inventory are included in other operating expenses in our consolidated statements of operations and comprehensive income (loss). 

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Income taxes

Our estimated federal and state effective income tax rate in 2013 of 37.4% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves.  We pledge our producing oil and gas properties to a syndicate of banks led by JPMorgan Chase Bank, N.A. to secure our revolving credit facility.  The banks establish a borrowing base, in part, by making an estimate of the collateral value of our oil and gas properties.  We borrow funds on our revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program.  Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves.  If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program.  However, we may mitigate the effects of product prices on cash flow through the use of commodity derivatives.

At December 31, 2012, we had $460 million of borrowings outstanding under our revolving credit facility, leaving $121 million available under the facility after allowing for outstanding letters of credit totaling $4.1 million. This level of liquidity did not permit us to continue capital spending at the same level we experienced in 2012. As a result, during 2013, we have taken and are taking steps to reduce debt and increase liquidity through a combination of lower capital spending, sales of certain producing properties and issuances of long-term debt to achieve what we believe is a sustainable balance between our future capital commitments and our expected financial resources. These actions include the following:

Reduce capital spending

We currently expect to spend $270 million in 2013 on exploration and development activities, representing a 38% reduction from 2012 spending levels. These lower spending levels, combined with proceeds from the sale of our Andrews County Wolfberry assets discussed below, are expected to permit us to reduce the outstanding balance on our revolving credit facility by more than $125 million.

Sale of Wolfberry Assets

On April 24, 2013 we closed a transaction to monetize a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities (the “Assets”). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. At closing, we contributed 5% of the Assets to a newly formed limited partnership in exchange for a 5% general partner interest, and a unit of GE Energy Financial Services contributed cash of $215.2 million to the limited partnership in exchange for a 95% limited partnership interest. The limited partnership then purchased 95% of the Assets from us for $215.2 million, subject to customary closing adjustments, with $25.9 million remaining in escrow pending resolution of certain title requirements. If the title requirements are not satisfied, waived or extended within 180 days, the affected properties will be conveyed back to us and the escrowed funds will be returned to the limited partner. As of October 15, 2013, the buyer has exercised its right to extend the post-closing cure deadline an additional 180 days. We believe that the defects will be cured timely.

Effective with the closing, the aggregate commitment and borrowing base under our credit facility was reduced from $585 million to $470 million to account for the release of collateral.

Also in April 2013, we sold a 75% interest in our rights to the base of the Delaware formation in approximately 12,000 net undeveloped acres in Loving County, Texas to a third party for $6.8 million in cash. Under the terms of the agreement, the third party is required to carry us for all drilling and completion costs on six wells attributable to our retained 25% working interest. We retained all rights to intervals below the Delaware formation, including the Bone Springs and Wolfcamp formations.

Throughout the year, we will also consider other asset sales and/or monetization transactions that enhance shareholder value and meet strategic operating and financial objectives.

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Joint Venture Reeves County Wolfbone Assets

We plan to seek a joint venture partner for a portion of our net interest in Reeves County Wolfbone assets through a joint venture arrangement in which we would expect to receive a combination of an upfront cash payment and a drilling carry. If acceptable terms to a joint venture arrangement are achieved, we anticipate closing the transaction during the fourth quarter of 2013 or the first quarter of 2014. However, we cannot make any assurances that we will be able to consummate any such transaction on terms acceptable to us.

Issuances of Long-Term Debt

On October 1, 2013, we used the net proceeds from our issuance of an additional $250 million aggregate principal amount of 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. After giving pro forma effect to the application of net proceeds from the issuance of the additional 2019 Senior Notes and the reduction in borrowing base, we increased our availability under our revolving credit facility to $323.4 million as of September 30, 2013.

Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the nine months of 2013 and our planned expenditures for the year ending December 31, 2013.

	Actual Expenditures Nine Months Ended September 30, 2013		Planned Expenditures Year Ending December 31, 2013		2013 Percentage of Total
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	67,800	$	106,900	39	%
Other	32,400		37,800		14	%
Austin Chalk/Eagle Ford Shale	50,300		67,000		25	%
Other	8,200		9,900		4	%
	158,700		221,600		82	%
Leasing and seismic	38,900		48,400		18	%
Exploration and development	$	197,600	$	270,000	100	%

Our expenditures for exploration and development activities for the nine months ended September 30, 2013 totaled $197.6 million.  We financed these expenditures for the nine months of 2013 with cash flow from operating activities and $43.7 million of advances under our revolving credit facility.  We currently plan to spend approximately $270 million on exploration and development activities during fiscal 2013.  Our actual expenditures during 2013 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year.  Factors, such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2013.

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow, combined with funds available to us under our revolving credit facility, will be sufficient to finance our planned exploration and development activities through 2013.  Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base may under our credit facility be less than expected, cash flow may be less than expected, or capital expenditures may be more than expected.  In the event we lack adequate liquidity to finance our expenditures through 2013, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.

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Cash flow provided by operating activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves.  We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash flow provided by operating activities for the nine months ended September 30, 2013 decreased $4 million, or 2.5%, as compared to the corresponding period in 2012 due primarily to the sale of our Andrews County properties.

Senior Notes

In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes.  The 2019 Senior Notes were issued at face value and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011.  In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000.  We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at September 30, 2013 and December 31, 2012.

Effective October 1, 2013, we issued an additional $250 million of aggregate principal amount of 7.75% Senior Notes due 2019. The notes were sold at 100% of par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture.

Revolving credit facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $470 million, limited to the amount of a borrowing base as determined by the banks.  We have historically relied on our revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs.  As long as we have sufficient availability under our revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment to eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.  In April 2013, the banks decreased the aggregate commitment and borrowing base under our revolving credit facility from $585 million to $470 million and decreased the maximum credit facility from $585 million to $470 million.  During the nine month period ended September 30, 2013, we decreased indebtedness outstanding under our revolving credit facility by $137 million, effective with the closing of the transaction to monetize our Wolfberry oil and gas reserves, leasehold interests and facilities in Andrews County, Texas for $215.2 million, of which $25.9 million is in escrow pending resolution of certain title requirements that we expect to resolve timely and apply the proceeds to further reduce our outstanding balance during the fourth quarter of 2013. On October 1, 2013, we used the net proceeds from our issuance of an additional $250 million aggregate principal amount of 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. In connection with the issuance of the additional 2019 Senior Notes, borrowing base was reduced to $407.5 million.

Our revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in our revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under our revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC.

40

At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year.  We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50%.  The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the nine months ended September 30, 2013 was 2.7%.

Our revolving credit facility contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities (“Consolidated Current Ratio”) of at least 1 to 1.  In computing the Consolidated Current Ratio at any balance sheet date, we must (1) include the amount of funds available under this facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives (non-cash assets or liabilities), and (3) exclude current assets and liabilities attributable to vendor financing transactions, if any.

Working capital computed for loan compliance purposes differs from our working capital computed in accordance with accounting principles generally accepted in the United States (“GAAP”).  Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under our revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives.  Our GAAP reported working capital was $31.4 million at September 30, 2013 compared to $3.6 million at December 31, 2012.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was $171.2 million at September 30, 2013, as compared to $117 million at December 31, 2012. 

The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at September 30, 2013 and December 31, 2012.

	September 30, 2013			December 31, 2012
	(In thousands)
Working capital per GAAP	$	31,423		$	3,556
Add funds available under our revolving credit facility	141,947			120,950
Exclude fair value of derivatives classified as current assets or current liabilities	(2,139		)	(7,495		)
Working capital per loan covenant	$	171,231		$	117,011

Our revolving credit facility also prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the last end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.  In connection with the issuance of additional Senior Notes due 2019 effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014.

We were in compliance with all financial and non-financial covenants at September 30, 2013 and December 31, 2012.  However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future.  If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend our revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means.  If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The lending group under our revolving credit facility includes the following institutions:  JPMorgan Chase Bank, N.A., Union Bank, N.A., Wells Fargo Bank, N.A., The Royal Bank of Scotland plc, Compass Bank, Frost Bank, Natixis, KeyBank, N.A., UBS Loan Finance, LLC, Fifth Third Bank, US Bank, N.A., and Whitney Bank.

 From time to time, we engage in other transactions with lenders under our revolving credit facility.  Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements.  As of September 30, 2013, JPMorgan Chase Bank, N.A. was the only counterparty to our commodity derivative agreements.  Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under our revolving credit facility.

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At September 30, 2013, we had $323 million of borrowings outstanding under our revolving credit facility, leaving $141.9 million available under the facility after allowing for outstanding letters of credit totaling $5.1 million.  After giving pro forma effect to the application of net proceeds from the issuance of the additional 2019 Senior Notes and the reduction in borrowing base, we had $323.4 million available as of September 30, 2013. Our revolving credit facility matures in November 2015.

Alternative capital resources

We have reduced our capital spending levels for fiscal 2013 to the extent necessary to be fully funded through a combination of operating cash flow, proceeds from asset sales and the issuance of debt.

We may also use other capital resources, such as entering into joint venture participation agreements with other industry or financial partners and issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2013 and subsequent periods. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

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Item 3 - Quantitative and Qualitative Disclosures About Market Risk

Our business is impacted by fluctuations in commodity prices and interest rates.  The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential effect of market volatility on our financial condition and results of operations and should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Part II - Item 7A of our Form 10-K for the year ended December 31, 2012.

Oil and Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  We cannot predict future oil and gas commodity prices with any degree of certainty.  Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources.  Based on December 31, 2012 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2012 would reduce our gross revenues for the year ending December 31, 2013 by $8.9 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production.  We do not enter into commodity derivatives for trading purposes.  When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity.  If the market price is greater than the put strike price, no payments are due from either party.  Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price).  If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price.  If the market price is between the call and the put strike prices, no payments are due from either party.  The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products.  In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements.  We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge.  If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received.  If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

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The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2013. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil			Gas
	Bbls	Price		MMBtu (a)	Price
Production Period:
4th Quarter 2013	300,000	$	104.60	330,000	$	3.34
2014	1,600,000	$	97.30	—	$	—
	1,900,000			330,000

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  As of September 30, 2013, a $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $1 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At September 30, 2013, our fixed rate debt maturing 2019 had a carrying value of $349.6 million and an approximate fair value of $348.3 million, based on current market quotes.  We estimate that a hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $15.3 million.  Based on our outstanding variable rate indebtedness at September 30, 2013 of $323 million, a change in interest rates of 100-basis points would affect annual interest payments by $3.2 million.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders.  Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to our disclosure controls and procedures:

• management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;

• this evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and

• it is the conclusion of our chief executive and chief financial officers that as of September 30, 2013 these disclosure controls and procedures are effective at the reasonable assurance level in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the nine months ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1A - Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements.  Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2012, as filed with the SEC on March 5, 2013, and available at www.sec.gov.

There have been no material changes to these risk factors. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or future results.

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Item 6 - Exhibits

Exhibits
**3.1	Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2	Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1	Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††
**4.2	Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.3	Registration Rights Agreement, dated as of September 26, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on October 2, 2013††
**10.1	CWEI Eagle Ford I Reward Plan effective January 1, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††
**10.2	CWEI East Permian Reward Plan effective January 1, 2007, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††
**10.3	Eighth Amendment to Second Amended and Restated Credit Agreement and Limited Consent dated September 17, 2013, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on September 23, 2013††
*31.1	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
***32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*101.INS	XBRL Instance Document
*101.SCH	XBRL Schema Document
*101.CAL	XBRL Calculation Linkbase Document
*101.DEF	XBRL Definition Linkbase Document
*101.LAB	XBRL Labels Linkbase Document
*101.PRE	XBRL Presentation Linkbase Document

*Filed herewith

**Incorporated by reference to the filing indicated

***Furnished herewith

††Filed under our Commission File No. 001-10924

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CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

		CLAYTON WILLIAMS ENERGY, INC.
Date:	November 5, 2013	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief Operating Officer
Date:	November 5, 2013	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibits
**3.1	Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2	Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1	Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††
**4.2	Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.3	Registration Rights Agreement, dated as of September 26, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on October 2, 2013††
**10.1	CWEI Eagle Ford I Reward Plan effective January 1, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††
**10.2	CWEI East Permian Reward Plan effective January 1, 2007, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††
**10.3	Eighth Amendment to Second Amended and Restated Credit Agreement and Limited Consent dated September 17, 2013, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on September 23, 2013††
*31.1	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
***32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*101.INS	XBRL Instance Document
*101.SCH	XBRL Schema Document
*101.CAL	XBRL Calculation Linkbase Document
*101.DEF	XBRL Definition Linkbase Document
*101.LAB	XBRL Labels Linkbase Document
*101.PRE	XBRL Presentation Linkbase Document

*Filed herewith

**Incorporated by reference to the filing indicated

***Furnished herewith

††Filed under our Commission File No. 001-10924

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